Method and system for measuring non-drilling times and their application to improve drilling unit efficiency

ABSTRACT

A method for measuring non-drilling times during well construction operations includes automatically determining a staring time and a stopping time of at least one non-drilling activity. An elapsed time between the starting time and the stopping time of the activity is recorded. The recorded time is normalized for at least one of a well depth and a water depth.

BACKGROUND

This disclosure is related to the field of subsurface well construction. More specifically, the disclosure relates to methods for measuring times of specific well construction activities to evaluate performance of individual drilling units and/or operating personnel in comparison to other drilling units and personnel.

The cost of wellbore construction, in particular marine drilling operations has risen substantially in recent years. Some well construction operations conducted in deep ocean water (water depth in excess of 3000 to 5000 feet) may now cost in excess of $1,000,000 per day. Land based drilling costs in excess of $50,000/day are common. These costs are driving the need for increased efficiency. The need for increased efficiency drives the need for measurement techniques to accurately determine the time used to perform well construction operations, both during active drilling (lengthening the wellbore) and auxiliary operations. Accurately measuring the time of specific activities allows review and improvement of drilling unit and operating personnel efficiency. Such improvement can result in reducing activity time and thus the cost.

Generally, when describing drilling rig operations and their related efficiency, what is meant is the time spent with the bit on bottom while drilling/sliding, tubular tripping times, conditioning the hole and responding to downhole conditions. Efforts are often focused on measuring and improving these operations with efficiency efforts. For convenience these will be referred to as “drilling times”.

Automatic measurement technology has allowed for drilling times to be calculated automatically using sensors and algorithm software to determine the drilling unit's state of operation. Examples of this automated technology are described in U.S. Pat. Nos. 6,892,812 and 6,820,702. These patents are primarily related to the automatic detection and measurement of times when the drilling unit is within “drilling times” operation, i.e., primarily using the unit's drilling equipment such as the draw works, rotary, mud pumps and tubulars. However the drilling unit also undergoes “non-drilling times” such as mooring/jacking up, preloading/ballasting, skidding drilling package, nippling up/testing blowout preventer equipment (BOPE), running/testing riser and choke and kill lines (C&K), installing slip joint/diverter, rigging up to cement/run casing, among other non-drilling operations.

“Non-drilling times” have proven more difficult to measure because of relatively unavailable sensors/automatic detection technology to facilitate measurement. The lack of easily identified and measured “start/stop” points of a function hampers measurement of non-drilling times. U.S. Pat. No. 7,886,845 B2 issued to King et al. describes a method that identifies these “non-drilling times” or “auxiliary times”, and detects, measures, and records their duration. The described method requires the use of additional sensors and a recording device to gather and display the sensor readings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows an example mobile drilling unit and placement of sensors on the unit that are used in connection with a system and method according to the disclosure.

FIG. 2 shows an example time recoding sequence for various drilling unit operations.

FIG. 3 shows an example data display of recorded times according to an example data recording sequence.

FIG. 4 shows an example of a floating mobile drilling unit that may be used with other examples of a system and method according to the disclosure.

FIG. 5 shows a table of MKPI broken down into KPI subsections.

FIG. 6 shows a table of normalized activity times.

FIG. 7 shows a measurement sequencer logic table.

DETAILED DESCRIPTION

Methods and apparatus for measuring non-drilling time will be explained below with reference to specific embodiments. The described embodiments are only intended to provide the reader with examples of automatic time recording apparatus and methods for purposes of implementing methods according to the present disclosure and such apparatus and methods should in no way be considered as limiting the scope of the present disclosure.

Methods and measurement apparatus will be described below first with reference to certain types of “bottom supported” mobile offshore drilling units. Later examples will be described in terms of mobile offshore drilling units that include a floating structure or platform that supports a drilling rig and associated equipment. Accordingly, it is to be clearly understood that the scope of the present disclosure is not limited to particular types of drilling units. The principles of the disclosure are equally applicable to any type of drilling unit that is movable from one drilling location to another, including “platform” rigs (rigs that are disposed on a fixed-position, water bottom supported structure) and requires certain acts to be performed to prepare the unit for drilling and for moving to a different drilling location. The principles of this disclosure are equally applicable to drilling units deployed on the land surface; accordingly, the scope of the disclosure is not intended in any way to be limited to marine drilling units. For purposes of land based drilling units, normalization of certain performance measurements may be made with respect to depth of a wellbore; reference to normalization for water depth (as well as wellbore depth) would be applicable to marine drilling units.

An example bottom supported mobile offshore drilling unit is shown in FIG. 1 at 10. The drilling unit 10 in the present example is called a “jackup” drilling unit. Such drilling units are supported by the water bottom 20 by legs 12 that can be moved along their longitudinal direction with respect to a hull 16 of the drilling unit 10 by operating jacking motors 12B. The jacking motors 12B may each turn a respective gear unit (not shown) the output of which is in contact with a rack 12A or similar linear gear-toothed structure on each leg 12. Other types of jackup drilling units may use a pinhole/hydraulic jacking system to move the legs, for example. The legs 12 may each include a “spud can” 12C at a bottom end thereof for contacting the water bottom 20 and supporting the weight of the drilling unit 10. During set up of the drilling unit 10 on a well location, the hull 16 floats and is moved in to the selected location by tug boats or similar towing vessels as the legs 12 are maintained substantially in their uppermost position with respect to the hull 16.

When the drilling unit 10 is disposed at the selected location, the hull 16 is positioned both geodetically and with the hull 16 in a preferred geodetic orientation. The legs 12 are moved longitudinally (called “jacking”) using the jacking motors 12B (or hydraulic motors in hydraulically jacked leg examples). Downward movement of the legs 12 with respect to the hull 16 eventually causes the spud cans 12C to contact the water bottom 20. When the spud cans 12C contact the water bottom 20, continued jacking of the legs 12 causes the hull 16 to move upwardly out of the water. The jacking continues until the hull 16 is positioned at a selected height (“air gap”) 22 above the mean water surface 18.

When the selected air gap 22 is obtained, a cantilever structure (“cantilever”) 14 may be laterally displaced from its transport position (generally entirely over the hull 16). Such lateral displacement, called “skidding out” the cantilever 14, may be performed by a cantilever skid motor 14B that rotates a gear (not shown) in contact with a cantilever skid rack 14A. Other examples of a cantilever may use a pinhole/hydraulic skidding unit in contact with the cantilever skid rack 14A. The skidding out continues until a drilling rig 29, supported generally near the outward end of the cantilever 14, is positioned over a proposed well location 31 on the water bottom 20. The drilling rig 29 may include pipe lifting, supporting and rotating devices familiar to those skilled in the art, for example, a derrick 24 in which is included a tubular or pipe rack 32 to vertically support assembled “stands” of tubulars 34 used in wellbore drilling, testing and completion operations. The rig 29 may include a winch called a drawworks 26 that spools and unspools wire rope or cable, called “drill line” 27, for raising and lowering a traveling block and hook 28. The hook 28 may support a top drive 30 or similar device for applying rotational energy to the pipe for various drilling and well completion operations.

In the present example, sensors may be associated with some of the foregoing drilling unit components to measure one or more parameters used in various aspects of methods according to the present disclosure. The parameters measured by the various sensors described herein may be characterized as being related to the beginning and the end of one or more non-drilling operations or “auxiliary operations.” As used in the present description, the term “auxiliary operations” is intended to mean any function or operation on the drilling unit 10 that is not related to equipment or devices being inserted into or removed from a wellbore (including the active drilling of such wellbore), but is nonetheless essential to enabling the drilling unit 10 to perform intended drilling operations. The above examples of jacking the legs 12 until the selected air gap 22 is obtained, as well as skidding the cantilever 14 are two of such auxiliary operations. Other examples of auxiliary operations and their use in methods according to the present disclosure will be further explained below.

As an example, each jacking motor 12B may include a sensor and an associated wireless data transceiver (shown at 11 collectively) for measuring electric current drawn by the respective jacking motor 12B. A similar wireless transceiver/sensor combination 11 may be associated with the cantilever skid motor 14B. A transponder, such as an acoustic or laser range finder, or a global positioning system receiver, shown at 36, may be disposed proximate a bottom surface of the hull 16 in order to measure the air gap 22. Such sensor 36 may also include an associated wireless transceiver 11. A data acquisition system (“DAQ”) 33 may be disposed at a convenient position on the drilling unit 10 and include a wireless transceiver 11A for receiving data from the various sensors, such as those described above. Although in the present example the various sensors include wireless transceivers 11 to communicate with the DAQ 33, it should be clearly understood that “wired” sensors may also be used in accordance with the disclosure.

The drilling rig 29 may also include sensors for measuring various parameters related to operation of the drilling rig 29. An example of such sensors and methods for validating and interpreting the measurements made by the rig sensors to automatically determine what drilling unit operation is underway at any time are described in U.S. Pat. No. 6,892,812 issued to Niedermayr et al. As shown in FIG. 1, one such sensor is may be a load cell 27A arranged to determine the total axial force (weight) supported by the drilling unit 29. The load cell 27A may be coupled wirelessly through a transceiver 11 to the DAQ 33. Such load cell is generally known in the art as a “weight indicator.” Another sensor may be a pressure/volume sensor 126 associated with pumps (not shown) configured to move fluid through appropriate rotary seals in the top drive 30 and into any pipe coupled to the top drive, such as a drill string or casing. The pressure/volume sensor 126 may include a pressure transducer (not shown separately) and a device known in the art as a “stroke counter” or similar device that measures a parameter related to the volume displacement of pistons within cylinders in a “mud pump.” The pressure volume sensor 126 may also be wirelessly coupled to the DAQ 33. The weight indicator (load cell 27A) and the pressure/volume sensor 126 may be used to make measurements related to the start and stop times of various operations as will be described below in more detail.

Having described an example drilling unit and examples of sensors for measuring parameters related to start and stop times of non-drilling operations, a more complete description of an example method using measurements from such sensors to characterize and display elapsed times for such operations will now be explained.

For a jackup drilling unit such as shown in FIG. 1, non-drilling operations performed prior to starting drilling of a wellbore are typically performed in a certain sequence. An example of such a sequence would include the following.

TABLE 1 1. Drilling unit is moved to selected location. 2. Drilling location is surveyed for positional accuracy and for presence of subsurface and water bottom hazards. 3. Hull is moved to five foot (1.6 meter) air gap. 4. The “water tower” is rigged up. 5. Preload is pumped. 6. Preload is discharged (“dumped”). 7. The hull is lifted to its final selected air gap. 8. Transportation securing devices are unlocked from the cantilever 9. The cantilever is skidded to its selected lateral position. Drilling fluid, air and hydraulic hoses, and electrical cable are connected between the drilling rig and equipment disposed in the hull. 10. Ropes are installed and equipment disposed on a supply vessel is unloaded. 11. A percussion hammer used to install “drive pipe” in the water bottom is inspected and serviced. 12. The hammer and “drive pipe” are lifted into position for installation by the drilling rig. 13. The drive pipe installation by the hammer is initiated.

Of the above listed auxiliary operations, certain ones may be described as “critical path” operations because they must be performed in a particular sequence in order for the drilling unit 10 to be capable of commencing drilling operations. The other auxiliary operations may be referred to as “off critical path” because they may be done concurrently with certain other operations (auxiliary and/or drilling) and/or out of sequence to some extent. The critical path and off critical path operations from the above example, and additional off critical path operations typically performed during set up of the drilling unit may include the following:

TABLE 2 Critical Path Operations Off Critical Path Operations Move unit onto location Rig up water tower; remove flanges Jack to 5 foot air gap Survey location; grease legs Pump preload Service hammer Dump preload Release cantilever transportation locks Jack to final air gap Grease cantilever skid out equipment Skid cantilever Offload equipment on vessel Lift hammer and drive pipe Install drive pipe

In the present example, the various sensors described with reference to FIG. 1 may be interrogated at selected intervals automatically by the DAQ (33 in FIG. 1). The DAQ 33 may include a programmable microprocessor (not shown separately) or similar programmable computing device capable of executing program instructions. The program instructions may be preloaded onto the processor or may be stored in a computer readable medium for loading at the system operator's convenience.

An example of elapsed time recording and characterization within the DAQ 33 is shown in a flow chart in FIG. 2. Upon arrival of the drilling unit (10 in FIG. 1) at the location, the DAQ 33 may be initialized. At 50, current drawn by the jacking motors (12B in FIG. 1) is measured, using sensors as explained above. The DAQ 33 may be programmed to begin recording time when the motor current increases over an amount associated with the legs moving through the water, as shown at 52. Such current amount may be associated with the legs (12 in FIG. 1) contacting the water bottom (20 in FIG. 1) so as to begin lifting the hull (16 in FIG. 1). The recording time may be stopped when the jacking motor current returns to zero, at 54. The elapsed time measured between the above start and stop times may be characterized as the amount of time performing the “jack to initial air gap” critical path operation, as shown at 51.

The DAQ 33 may be programmed to query the various sensors on the drilling unit, and determine a start time for pumping preload from the measurements made by certain of the sensors. For example, a pump used to pump preload (not shown in the figures) may have its current measured. When the pump current is switched on as measured by the associated sensor, the DAQ 33 may be programmed to begin recording elapsed time, as shown at 56. When the pump current is switched off, recording of elapsed time may stop, as shown at 58. Elapsed time recorded by the DAQ 33 may be characterized as the “pump preload” critical path operation, as shown at 53.

A valve (not shown) used to dump preload may include a position sensor to determine when the valve is open or closed. The DAQ 33 may be programmed to start recording time, at 58, when the preload valve is opened. The recording may be stopped, at 60, when the jacking motor current is greater than zero, shown at 62, indicating that the preload has been dumped sufficiently to enable jacking the hull to the final air gap. The foregoing elapsed time may be characterized as the “dump preload” critical path operation, as shown at 55. Concurrently with the stop time of the “dump preload” operation, the DAQ 33 may be programmed to initialize elapsed time for the “jack to final air gap” operation when the jacking motor current is switched on. The stop time of the jack to final air gap operation may be triggered in the DAQ 33 by, for example, when the jacking motor current is switched off, or when the sensor (36 in FIG. 1) detects that the selected air gap has been obtained.

When the skid motor current is detected as having been switched on, at 66, the DAQ 33 may be programmed to begin recording elapsed time. The recording may be stopped when the skid motor current is switched off, at 68. The recorded elapsed time, at 59, may be characterized in the DAQ 33 as for the “skid out cantilever” operation, at 59.

At 70, current for a motor used to operate the drawworks (26 in FIG. 1) may be measured. When the current is switched on, the DAQ 33 may begin recording elapsed time. Recording may be stopped when a first hammer strike is detected. Such strike detection may be obtained by measuring, for example, air or hydraulic pressure used to operate various components on the rig (29 in FIG. 1) or by including a vibration sensor (not shown) in the pneumatic or hydraulic power unit of the hammer. The recorded elapsed time may be characterized in the DAQ 33 as the operation “pick up hammer” at 61. Concurrently with detection of the first hammer strike at 72A, the DAQ 33 may be programmed to begin recording elapsed time until, for example, drawworks motor current measurements or hookload indications correspond to having laid the hammer down out of the rig, as shown at 74. The elapsed time may be characterized in the DAQ 33 as the operation “run drive pipe.”

In the present example, the DAQ 33 may be programmed so that notwithstanding measurements made by the various sensors as being indicative of a start or stop time of a particular operation, the determined start and stop times of certain auxiliary operations must take place in a predefined sequence. By programming the DAQ 33 to determine start times and stop times of certain events in a predefined sequence, and thus to record elapsed times in a predefined sequence, the possibility of false time recording (time allocated to an operation not consistent with the actual operation underway) will be reduced. An example of such a predefined sequence includes the events shown in their respective order in Table 1. Sensor measurements made by the various sensors may be used to determine start time of a particular operation only when all prior operations in the predefined sequence have been determined to be completed.

The time recording programming instructions for the DAQ 33 may also include recording elapsed time between the end or stop time of one of the above operations and the start time (where not concurrent therewith) of the succeeding operation in the predefined sequence. Such times are shown in FIG. 2 as “hidden times” 65, and in some cases such hidden times may be associated with activities on the drilling unit that require human activity or require intervention by personnel on the drilling unit. The hidden times 65 each may be further characterized with respect to the two operations that are adjacent thereto in the drilling unit set up sequence (the predefined sequence for programming the DAQ 33).

Time recordings made and characterized as explained above may be displayed in various formats for evaluation by the system operator. The time recording display may be made on any suitable computer display, including a cathode ray tube or liquid crystal display, a printer, or any similar display device. An example display format is shown in FIG. 3. The upper bar graph in FIG. 3 may represent elapsed times recorded for various operations described above. The size of each bar 80 may represent time for each of the operations (1 through 6) on the coordinate axis of the graph. The hidden times between successive operations may be displayed on the same or a different graph. In FIG. 3, the hidden times are shown at 65. The upper bar graph may represent, for example, operations conducted on a first well in a particular operating area. A lower graph in FIG. 3 may represent corresponding operations for a different well in the same or a different operating area. The operating times are shown at 80A and the hidden times are shown at 65A in FIG. 3 for such subsequent well.

The system operator may use the displayed times to evaluate a number of different performance criteria. For example, the hidden times may be used to evaluate the efficiency of different personnel on the drilling unit. The operating times may be used to evaluate whether the equipment associated with each particular operation is functioning properly, and/or whether the particular personnel operating such equipment are doing so correctly and/or efficiently.

Having explained an example of a method according to the disclosure used on a bottom supported drilling unit (jackup), an example implementation of a method according to the disclosure on a floating drilling structure follows.

One procedure on a floating drilling structure is “Mooring/Anchoring up.” Such procedure includes deployment of mooring lines to a device that fixes their position with respect to the water bottom so that the floating drilling structure will remain substantially fixed during drilling operations. Measurements made for such time interval includes the time to moor up each individual mooring line and the efficiency of each of the Anchor Handling Vessels (“AHV”). Such time interval may be measured, for example, beginning when an AHV begins to pull on is respective mooring line. A record of the tension exerted on a tension measuring device associated with the mooring line maybe used to start and stop recording the mooring line deployment time. The time period may end when the AHV releases the mooring, and tension is released as indicated by the mooring line tension indicator.

Another measurement associated with a floating drilling unit is the AHV switching/hookup & tensioning efficiency. The time interval measured may be that needed for the AHV to reposition and rig up onto another mooring. Such time period may begin when the mooring tension is released from the previous mooring, as indicated by the tension indicator. The time period may end when tensioning begins on the subsequent mooring as indicated by the tension indicator. A total time for setting and testing all anchors may be recorded from the above time periods.

The time required to tension the moorings to the required tension after setting all moorings may also be recorded. Such time may be the sum of the individual mooring line times as explained above, the switching/hookup times and bringing moorings to final required tensions. Such time interval may begin when the AHV begins to tension the first mooring and may end when final tensions on all moorings are completed.

Another time interval that may be measured includes an AHV retrieval wire line speed. Such interval may includes the time required to retrieve the AHVs retrieval wire after setting the anchor so as to begin the next anchor deployment and setting. The interval may begin when the anchor is on bottom and the floating drilling platform begins to tension up on the mooring line. The interval may end when the AHV is connected to subsequent mooring and begins apply tension on the next mooring as indicated by the mooring tensioning device.

Other examples of floating drilling platform procedures and time interval measurements may be found in the table below.

TABLE 3 Procedure Purpose Interval Start Event Interval Stop Event Blowout Measure the time Skid out BOP cart as BOP is lifted off the preventer required to connect the indicated by BOP cart BOP cart with the first (“BOP”) multiplex lines, slope skidding motor current joint riser as indicated Running indicators and installing or hydraulic pressure by rig's weight indicator Times the first joint of riser or load sensor on the Riser Spider Riser running Measures the time to When riser joint is When the riser string and connection pick up and add a joint picked up as indicated with the new riser joint times of riser to the riser by the rig's weight added is picked as string as indicated by indicator or load sensor indicated by the drilling the time the riser is on the Riser Spider rig's weight indicator landed on the riser spider. Choke and Kill Measure the amount of When the riser is in riser When test pump line (“C&K”) time required to fill the spider as indicated by pressure indicates a testing times C&K lines, booster line the drilling rig weight steady test pressure on and install the test cap, indicator or load sensor the C&K lines and test the lines. on the Riser Spider Pick up and Measure the time to When riser string is set When the slip joint is Install Slip pick up and install the in riser spider as picked up, (different Joint slip joint in the riser indicated by the drilling weight of typical riser string rig weight indicator or joint) installed in string load sensor on the Riser then riser string with Spider slip joint is picked up as indicated by the drilling rig weight indicator or load sensor on the Riser Spider From start Measures the time to Start testing BOP as When BOPE test testing to begin testing BOPE to indicated by the BOP complete and drill pipe finish testing finish testing BOP, control panel, cement test string is tripped out BOP C&K lines, Choke pump and test chart of hole and set back as equipment manifold, and inside indicated by weight (BOPE) BOPs indicator

An example floating mobile offshore drilling unit is shown in FIG. 4 at 10A. The unit 10A shown in FIG. 4 is known as a “semisubmersible” drilling unit. The following description is equally applicable to other types of floating drilling units, such as drill ships. The unit 10A includes a drilling deck 90 that may be supported above the surface of the water 18 by floatation devices such as pontoons 92. The drilling deck 90 is coupled to the pontoons 92 by columns 91 such that when the pontoons 92 are submerged to a selected depth below the water surface 18, the drilling deck is supported at a selected height above the water surface 18. The type of floating drilling unit shown in FIG. 4 is also known as a “moored” unit, in that the geodetic position of the unit is maintained by a mooring system. The mooring system includes winches 104 that retrievably deploy mooring lines 106 through fairleads 103 to anchors 108 fixed on the water bottom 20.

In the example shown in FIG. 4, the winches 104 may each include a motor current sensor, hydraulic pressure sensor or other device, shown generally at 111, that detects operation of the respective winches 104. Output from the winch sensors 111 may be wirelessly (see 11) communicated to the DAQ (see 33 in FIG. 1). The drilling deck 90 may support a drilling rig 29. The drilling rig 29 may be configured substantially as explained with reference to FIG. 1. For purposes of the invention, sensors and equipment associated with the drilling rig 29 will be substantially the same irrespective of whether the drilling unit is a floating structure as in FIG. 4, or is a bottom supported structure as shown in FIG. 1. Floating drilling units typically provide that a marine riser 94 is coupled between the unit 10A and a subsea BOP stack 100. The BOP stack is typically coupled to the upper end of a surface casing 102 placed in the well immediately below the water bottom 20. Various operations related to assembling the marine riser 94 and BOP 100, including testing choke and kill lines 96 and multiplex cables 98 are explained above. Testing the BOP 100 is typically performed on a suitable fixture (called a “stump”—not shown) disposed on the drilling deck 90.

Although not shown separately in FIG. 4, those skilled in the art will appreciate that the drilling rig 29 in FIG. 4 may include similar equipment and sensors as the drilling rig shown in FIG. 1. Accordingly, certain operations for which start and stop times make use of measurements made by the various sensors associated with the drilling rig 29 are equally applicable to both the bottom supported drilling unit shown in FIG. 1 and the floating drilling unit shown in FIG. 4.

It is also within the scope of the present invention to measure start and stop times of certain activities related to completion of a wellbore. “Completion” of a wellbore is generally understood to mean placing a pipe or casing in the well and installing particular equipment used to move fluids, or assist in such motion, from within a subsurface Earth formation to the Earth's surface. Examples of completion related actions and their corresponding time intervals may include the following:

TABLE 4 Procedure Purpose Interval Start Event Interval Stop Event Rig up and Time to rig up to pull Pull protective corrosion Pick up the Blowout install tubing corrosion cap, rig up cap, install tubing head Preventers (BOP) from head assembly and install tubing head assembly as indicated the test stump as time by hydraulic release indicated by hydraulic pressure release pressure and rig's weight indicator. Run and test Measure and evaluate Pick up the BOP from Finish testing BOPs as BOPs time needed to run and the test stump as indicated by cement test BOP equipment indicated by hydraulic pump steady pump release pressure and pressure and test chart rig's weight indicator Pressure & Test Subsea Tree just Start pressure and When function test and function Test prior to running to sea function test as pressure tests are Subsea Tree on floor indicated by cement or complete as indicated test stump Subsea Tree control by cement pump and panel test chart Skid Subsea Skid the Subsea Tree to When function test and When rig up is complete Tree to the moonpool in pressure tests are and Subsea Tree is moonpool & rig anticipation of running complete as indicated picked up off the test up to run to seafloor by cement pump and cart as indicated by test chart weight indicator

It should be clearly understood that the present disclosure is not limited to the particular procedures and time intervals in the above examples. The above examples are meant only to illustrate the principle of such methods and how methods according to the present disclosure may be used to improve the efficiency with which a drilling unit operates, particularly as such efficiency relates to non-drilling operations.

Although there are a plurality of different auxiliary operation (non-drilling) times as described in U.S. Pat. No. 7,886,845 B2, for purposes of the present disclosure, most of a drilling unit's non-drilling times may be categorized into segments generally centered around and just after running casing and/or liner (casing being a conduit extending from a selected depth in the well to the well surface; liner being a conduit extending from a selected depth in the well to the bottom of a previously installed casing). These time segments may be referred to as Major Key Performance Indicators (MKPI) and a substantial portion of a drilling unit's total non-drilling times may be measured using only a relatively small number of (about ten) MKPIs. For example, on a floating drilling platform some of the MKPIs are listed below in Table 5. Later it will be shows that MKPIs may have significant Key Performance Indicator (KPI) sub-sections.

TABLE 5 MKPI Description 1 Mooring 2 Rig up and Drill/Jet Structural Casing 3 Log (perform well logging operations), Run and Cement Conductor casing 4 Log, Run Surface Casing, Run and Test Blowout Preventer Equipment 5 Log, Run, Cement First Intermediate Casing (if used) 6 Log, Run, Cement Second Intermediate Casing (if used) 7 Plugging & Abandoning

For example, the MKPI “Drill, Log, Run Surface Casing, Run and Test Blowout Preventer Equipment may be separated into KPI sub sections as shown in the table in FIG. 5.

Each measured MKPI time cannot be compared to the corresponding MKPI on other drilling units or with other operating personnel on the same drilling unit without further processing the measured MKPI times according to the present disclosure. Such inability to compare raw measured MKPI times is due to the fact that the elapsed time of each MKPI includes well depth or water depth related KPIs such as running casing, riser, and drill pipe. In order to obtain valid comparisons, the MKPI times may be modified (normalized) to adjust for water or well depth related elapsed time. This adjustment will enable the same modified MKPI time to be measured and compared the corresponding MKPI time for different drilling units and/or drilling personnel (“drilling crews”) on the same drilling unit.

In one embodiment, the adjustment to the raw measured MKPI times may be performed by eliminating MKPI sub sections (e.g., KPIs) that pertain to water depth, well depth or depth-dependent operation times such as tripping pipe, running riser and cementing. By eliminating the components of MKPIs related to well depth or water depth, different drilling crews and/or different drilling units' non-drilling operations may be compared on an equal basis as the modified measured time segments now allow comparison of identical drilling unit activities. This is a fast and inexpensive way to measure non-drilling times as there is no need for additional sensors and recording devices. The drilling unit's existing sensors and recorders (e.g., the DAQ 33 in FIG. 2) may be used to record the modified MKPIs.

Automatically Measuring Start/Stop Times

It will be necessary to be able to automatically measure the start and stop times of any MKPI. There are several systems known in the art that may provide modified MKPI start and stop times. One such system is described in U.S. Pat. No. 6,892,812 and is sold under the trademark PRONOVA, which is a registered trademark of TDE Thonhauser Data Engineering GmbH, Leoben, Austria. Similar data may also be available from systems sold by Pason, USA, Inc. or National Oilwell Varco which are in common use in the industry. In each of the foregoing example systems, measurements made by various sensors ordinarily disposed on the drilling unit for measuring, e.g., hookload, top drive elevation, mud pump flow rate and/or pressure, tubular rotation speed may be used and the data recording unit may be programmed to determine automatically which activity is being undertaken at any time using the sensor measurements. An example of the foregoing is described in the '812 patent cited above. Other systems may be substantially as explained with reference to FIGS. 1 through 4 herein.

Normalizing the MKPI Time

In one example embodiment, and referring to FIG. 6, a table of KPIs is shown that may comprise the MKPI “Log, Run Surface Casing, Run and Test Blowout Preventer” (MKPI number 7 in Table 5). Those KPIs identified with an asterisk in FIG. 6 depend on water depth and on well depth. Such KPIs may be omitted from the total measured time of the MKPI. By omitting the elapsed times for each water or depth dependent KPI from a MKPI, a comparison of elapsed times for the same MKPI between different drilling units or between different drilling crews on the same drilling unit may be made on equal bases as elapsed times related to well depth and water depth in each non-drilling operation are eliminated from the total time measured.

Measuring such depth-normalized non-drilling times may provide a benchmark of a particular drilling unit's or drilling crew's operating efficiency. Normalized MKPI times may be compared with the same normalized MKPIs of other drilling units or drilling crews for efficiency comparison. The DAQ (33 in FIG. 1) may be programmed to compare measured MKPI elapsed times between different drilling crews on the same drilling unit and record and/or display the comparison in any convenient form. The DAQ (33 in FIG. 1) may receive data communicated from other drilling units to compare corresponding MKPIs and to record and/or display the comparison results.

Some drilling units are equipped with two separate hoisting units and tubular lifting and rotating equipment, e.g., top drives (called “dual activity” drilling units). Such drilling units may provide “off line” (meaning the hoisting and rotation system used to drill the well is not used for tubular assembly/disassembly) drilling/casing stand make up capabilities that have been shown to provide increased efficiency in non-drilling activities. The advantages of such drilling units' capabilities have been difficult to measure in the past, but could be easily measured and compared using a method according to the present disclosure. In one embodiment, each lifting and rotating equipment arrangement's non-drilling times may be measured and recorded so to be able to easily compare non-drilling MKPIs between different “dual activity” drilling units.

The MKPI times may contain considerable non-drilling time as it would contain many sub section KPIs as those shown without an asterisk in FIG. 6. However, if additional “drill down” into the sub section of a MKPI is needed for further efficiency improvements then the process described in U.S. Pat. No. 7,886,845 B2, for example, may be used.

Data Recording Sequencer Logic

Accurately measuring the activity time in the well construction process is important. Well data such as casing sizes and casing shoe depths along with hole (drill bit) sizes may be entered into the well program operating logic (e.g., in the DAQ 33 in FIG. 1) as input parameters. Additionally it is possible to include logic into the program that would track the well construction progress. An example of such logic for a jack up rig is shown in FIG. 7. The logic algorithm may be configured to anticipate successive actions in constructing the well and thus may be programmed to interrogate the proper sensors for each such action. In one example, a data recording sequencer may be programmed to measure elapsed time for both drilling operations and non-drilling (auxiliary) operations described above with reference to FIGS. 1 through 4. The data recoding sequencer described herein may be modified to use sensor measurements related to drilling activity as well as non-drilling (auxiliary) activity. However the system is configured, it is within the scope of the present disclosure to record non-drilling activity in a predetermined sequence, and to generate a record of the non-drilling activity times specifically unrelated to water depth or well depth as explained with reference to FIG. 6.

In some embodiments, all the recorded non-drilling activity times may be normalized by dividing the measured non-drilling activity times by the well depth or the water depth, whichever is related to the particular non-drilling activity time being recorded. For example, the KPIs identified with an asterisk in FIG. 6 may have their measured elapsed time divided by the well depth or water depth existing at the time the KPI elapsed times are measured. Either non-evaluation of the depth related non-drilling activity times or dividing by the well depth or water depth may be considered forms of normalizing the measured non-drilling activity times for the relevant depth.

A method according to the present disclosure may provide a quick and effective method for measuring gross non-drilling times and as such, may provide a method for improving efficiency in drilling unit non-drilling times.

A drilling unit using a system and methods according to the various aspects of the disclosure may provide improved efficiency with respect to auxiliary operations than drilling units that do not use such system and methods. A system and methods according to the invention may provide operators of such drilling units with diagnostic capability to determine sources of inefficiency in auxiliary operations and suggest corrective action or actions to improve efficiency.

While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims. 

What is claimed is:
 1. A method for measuring non-drilling times during well construction operations, comprising: automatically determining a starting time and a stopping time of at least one non-drilling activity using measurements from at least one sensor disposed on a drilling unit; recording an elapsed time between the starting time and the stopping time of the at least one non-drilling activity; and normalizing the recorded elapsed time for at least one of water depth and well depth.
 2. The method of claim 1 wherein the non-drilling activity comprises at least one of mooring, rigging up and drilling structural pipe, running and cementing conductor casing, running surface casing, running and testing blowout preventer equipment, running and cementing a first intermediate casing, running and cementing a second intermediate casing, well logging and plugging and abandoning a well.
 3. The method of claim 1 wherein the normalizing comprises at least one of exclusion of recorded non-drilling activity time when the non-drilling activity is related to well depth or water depth, and dividing the recorded non-drilling activity time by the respective water depth or well depth when the non-drilling activity is related to the well depth or the water depth.
 4. The method of claim 1 further comprising comparing the normalized elapsed time of one drilling unit to a normalized elapsed time for the same non-drilling activity determined on at least a second drilling unit.
 5. The method of claim 1 further comprising comparing the normalized elapsed time for the non-drilling activity performed by one drilling crew on the drilling unit with a normalized elapsed time for the same non-drilling activity performed by at least a second drilling crew on the drilling unit.
 6. A system for monitoring non-drilling operations on a drilling unit, comprising: at least one sensor configured to measure a parameter related to a start time and a stop time of at least one non-drilling operation on the drilling unit; a data acquisition device configured to determine a start time and a stop time of the at least one auxiliary operation from measurements made by the at least one sensor, the data acquisition device including a data recorder for recording elapsed time between the start time and the stop time, the acquisition device configured to determine start and stop times of the at least one non-drilling operation in response to the measurements, the data acquisition device configured to normalize the recorded elapsed time for at least one of water depth and well depth.
 7. The system of claim 6 wherein the non-drilling activity comprises at least one of mooring, rigging up and drilling structural pipe, running and cementing conductor casing, running surface casing, running and testing blowout preventer equipment, running and cementing a first intermediate casing, running and cementing a second intermediate casing, well logging and plugging and abandoning a well.
 8. The system of claim 6 wherein the normalizing comprises at least one of exclusion of recorded non-drilling activity time when the non-drilling activity is related to well depth or water depth, and dividing the recorded non-drilling activity time by the respective water depth or well depth when the non-drilling activity is related to the well depth or the water depth.
 9. The system of claim 6 wherein the data acquisition device is further configured to compare the normalized elapsed time of one drilling unit to a normalized elapsed time for the same non-drilling activity determined on at least a second drilling unit, the data acquisition device is further configured to at least one of record and display the comparison.
 10. The system of claim 6 wherein the data acquisition device is further configured to compare the normalized elapsed time for the non-drilling activity performed by one drilling crew on the drilling unit with a normalized elapsed time for the same non-drilling activity performed by at least a second drilling crew on the drilling unit, the data acquisition device is further configured to at least one of record and display the comparison.
 11. The system of claim 6 wherein the data acquisition device is configured to determine the start and stop times of the at least one non-drilling operation in response to the measurement only within a predetermined sequence of additional non-drilling operations. 